At the end of 2003, the American
Geophysical Union issued an unequivocal message: "Human activities
are increasingly altering the Earth's climate. . . . A particular concern
is that atmospheric levels of carbon dioxide may be rising faster than
at any time in Earth's history, except possibly following rare events
like impacts from large extraterrestrial objects."

Barring an asteroid strike, human production of CO2 is not
likely to slow down soon  and there's an urgent need to find somewhere
besides the atmosphere to put it. Sequestration in the ocean and in soils
and forests are possibilities, but another option, sequestration in geological
formations, already has a head start.

"The likeliest places to store CO2 are depleted oil and
gas reservoirs," says Karsten Pruess of Berkeley Lab's Earth Sciences
Division. He notes that porous reservoir rock can soak up gas, and caps
of impermeable rock can seal that gas in place over geologic lengths of
time. "The very existence of natural gas in a reservoir proves it
is capable of long-term storage."

Energy companies have long practiced pumping CO2 back into
the ground to force more oil out of depleting reservoirs. Unfortunately,
says Pruess, "depleted reservoirs don't have enough capacity to store
the huge amounts of carbon dioxide we're producing, and often they're
too far from stationary sources, like power plants and refineries, where
it's practical to collect CO2."

An attractive storage alternative to depleted reservoirs is saline aquifers.
In these formations, beds of porous sandstones containing very salty water
 with a salinity comparable to that of sea water, thus not a potential
source of drinking water  alternate with impermeable shales.

The only place where carbon dioxide injection into a saline aquifer is
already in use is the Sleipner natural-gas field in the North Sea, operated
by Statoil of Norway. Some of the natural gas tapped by Statoil contains
9 percent CO2, which has to be reduced to 2.5 percent before
it can be sold. After removal at a treatment platform at sea, the excess
CO2 is reinjected into a massive sandstone formation a kilometer
deep.

These are the ideal elements of geologic sequestration: concentrated
CO2 production close to deep saline aquifers. One region in
the United States, the Gulf Coast of Texas, meets both these requirements
in spectacular fashion.

A natural laboratory

Few places on Earth have a higher concentration of refineries, power
plants, and other fixed CO2 sources than the Texas Gulf Coast.
At over 160 million metric tons (in 1999), Texas produces almost twice
as much CO2 as runner-up California among U.S. states, more
than the entire United Kingdom.

The Gulf Coast of Texas has a high
concentration of refineries, power plants, and other fixed CO2
sources, conveniently located atop enormous beds of deep saline aquifers.

These numerous sources of recoverable carbon dioxide waste sit atop enormous
beds of deep saline aquifers, which formed as the gradually-rising mountains
to the west continually eroded into the warm sea that once occupied the
middle of North America. Periodic inundations by the ancient seas capped
the sands with beds of clay, which under increasing weight and pressure
metamorphosed into impermeable layers of shale. Today these sediments
lie thickly along the entire Gulf Coast of Texas, extending into Mexico,
Lousiana, and Mississippi.

The Texas Bureau of Economic Geology, centered at the University of Texas
at Austin, has recently begun a pilot program for carbon dioxide sequestration
in the region. Pruess and other members of the Earth Sciences Division
have partnered with the Bureau's Gulf Coast Carbon Center to develop computer
models that can better simulate what's likely to happen when carbon dioxide
and other byproducts are injected into the Gulf Coast's bedded sandstone-shale
sequences.

Key to these simulations is Berkekey Lab's versatile TOUGH2 general-purpose
numerical simulation program. The predecessors to TOUGH2 were created
20 years ago to model the flow of heat and fluids, in multiple phases,
through porous and fractured media like sand and rocks. Originally designed
for modeling fluid flow in geothermal reservoirs, the program has been
applied to a wide range of studies including the movement of pollutants
underground, such as nuclear waste. TOUGH2 is currently in use by approximately
300 organizations in more than 30 countries.

Realistic modeling of CO2 injection is more complex than simply
calculating its movement through sand and rock, however. A formation's
storage capacity depends not only on its porosity and other structural
properties but on its chemistry. And few industrial sources emit pure
carbon dioxide; instead, the CO2 is likely to be mixed with
other acidic gases, including such unpleasant contaminants as hydrogen
sulfide or sulfur dioxide.

Even pure carbon dioxide reacts differently with different kinds of aquifer
rocks. In limestone (calcium carbonate), chemical reactions with CO2
dissolved in brine can't increase the rock's capacity to absorb carbon
by much. But in impure sandstone, the dissolved carbon dioxide may react
to form solid carbonates that precipitate out of solution, fixing more
carbon. And in rocks composed predominantly of magnesium iron silicates,
reactions can precipitate so much carbonate it not only fixes a lot of
carbon but may clog the rock's pores.

A version of TOUGH2 called TOUGHREACT was recently developed by Pruess
and his colleagues Tianfu Xu, Eric Sonnenthal, and Nicolas Spycher to
address processes like acid mine drainage, waste disposal, and groundwater
quality, where chemistry plays a critical role. The program considers
fluid dynamics (as Pruess describes it, "how to push a dense gas
into the ground") in concert with chemical reactions and the effects
of heat and pressure.

Geochemist John Apps helped apply TOUGHREACT to the problem of CO2
sequestration in the sediments of the Gulf Coast's Frio and Jasper formations.
The modelers set out to analyze the transfer of CO2 and other
compounds between shale and sandstone layers, the consequent immobilization
of the gases through mineral precipitation, and the impact of cocontaminants
like hydrogen sulfide and sulfur dioxide.

"The key to modeling these systems is to incorporate accurate geochemical
data," says Apps, "and then to validate what the model predicts
against actual experience in the field." Apps, Xu, and Pruess presented
the results of their work at the 2003 meeting of the American Geophysical
Union in San Francisco.

The chemistry of the rocks

Over the past several decades, tables of the chemical properties of
thousands of rock-forming minerals have been painstakingly compiled from
laboratory experiments, which seek to determine phase equilibria, heat
capacities and heats of solution, and mineral solubility. These studies
typically subject a few grams of a solid sample or a solution to varying
pressures and temperatures using a raft of experimental devices, including
furnaces and "rod bombs," together with other independent investigative
techniques.

Laboratory experiments on mineral
samples, like this sandstone from a deep saline aquifer on the Texas
Gulf Coast, determine chemical and thermodynamic properties.

The tables are used to calculate the thermodynamic properties of sets
of minerals in systems at different temperatures and pressures; one aim
is to determine under what conditions minerals are stable, and when they
may dissolve and exchange chemical constituents with liquid and gas phases.

"Huge studies have been made to calculate the thermodynamic properties
of minerals," says Apps, citing as an example the pioneering work
of his colleague Harold Helgeson, a UC Berkeley geochemist who with his
co-workers published such a comprehensive review and tabulation in the
late 1970s. But tables compiled by different researchers using different
techniques and different sources of information may disagree significantly.
"A tendency to uncritically combine data bases can be a real mistake,"
Apps warns.

Even with consistent and dependable measurements, problems arise in applying
the data to physical processes like carbon sequestration. Apps notes that
much of Helgeson's initial work "was done on minerals that form igneous
and metamorphic rocks, which reach equilibrium at high temperatures and
pressures. The carbon-sequestration processes we're interested in occur
at relatively low temperatures and pressures. Calculation requires a large
extrapolation, which increases uncertainty."

Apps characterizes his role in applying the TOUGHREACT simulation program
to CO2 sequestration in the Gulf Coast saline aquifers as one
of "looking at the chemical systems, identifying the minerals involved,
calculating their thermodynamic properties, and making sure there is internal
consistency among all the minerals in the system." It's a task that
often requires recalculating from scratch, using the original raw data
of laboratory experiments or drawing on new experiments.

Although Apps has "strongly held views" about what processes
still need to be incorporated and fine-tuned in the TOUGHREACT program
 for example, an understanding of the rules by which various minerals
precipitate out of solution in order of their relative degree of instability
 he says, "Our recent simulations have been eerily similar
to what we observe in the field."

What may be particularly significant, Apps says, is that by modeling
"we can see the evolution of the system in all its complexity. Too
often field geologists are like the blind men feeling the elephant: they
find one property of the system and ignore the others. We can see the
whole elephant  albeit through a fuzzy lens."

TOUGH-code pioneer Karsten Pruess is excited about the successes TOUGHREACT
is already racking up. Not only has the program contributed to a better
understanding of proposed carbon sequestration along the Texas Gulf Coast,
TOUGHREACT is also being adapted for applications as far afield as the
Caspian Sea, where sulfur-laden crude oil and "sour gas" pose
particular problems of separation and sequestration.

"The development of these codes has always been problem-driven,"
says Pruess. "Although much of our attention has been devoted to
reservoir engineering and to studying the movement of wastes and pollutants,
the recent work with the Gulf Coast saline aquifers has addressed the
important question of whether we can use these codes to model natural
systems. And indeed, we've shown that TOUGHREACT simulations handle these
very well."

It would be hard to overstate the potential benefits. According to the
Department of Energy's Office of Fossil Energy, deep saline formations
in the United States may have the capacity to store up to 500 billion
metric tons of carbon dioxide  enough to store all the CO2
produced in the country, at present rates, for a century or more.